MANAGEMENT'S DISCUSSION AND ANALYSIS
SEPTEMBER 30, 2021
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is management's discussion and analysis ("MD&A") of Kolibri Global Energy Inc.'s ("KEI" or the "Company") operating and financial results for the three months and nine months ended September 30, 2021, compared to the corresponding period in the prior year, as well as information and expectations concerning the Company's outlook based on currently available information. The MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three months and nine months ended September 30, 2021 and the audited consolidated financial statements and MD&A for the year ended December 31, 2020. The condensed consolidated interim financial statements have been prepared in accordance with International Accounting Standard 34 "Interim Financial Reporting". The reporting and measurement currency is the United States dollar. Additional information relating to KEI including its Annual Information Form is filed on SEDAR at www.sedar.com and on the Company's website at www.kolibrienergy.com.
This report is prepared as of November 10, 2021. Please read carefully the important cautionary notes regarding technical information, forward-looking statements and other matters set out in this report.
Description of Business
KEI is an international energy company focused on finding and exploiting energy projects in oil, gas and clean and sustainable energy. Through various subsidiaries, the Company owns and operates energy properties in the United States. The Company continues to utilize its technical and operational expertise to identify and acquire additional projects. The common shares of the Company trade on the Toronto Stock Exchange ("TSX") under the symbol "KEI" and on the Over the Counter QB ("OTCQB") under the symbol "KGEIF".
Going Concern
The financial statements have been prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business.
At September 30, 2021, the Company had a working capital deficiency of $4.1 million. At September 30, 2021, the outstanding balance of the credit facility was $17.3 million. Subsequent to quarter end, the Company made principal payments of $0.2 million. The Company received its latest bank borrowing base redetermination in September 2021. As part of the redetermination, the term of the loan was extended to June 2023 and the Company will make additional principal payment reductions to reduce the borrowing base to $16.0 million by April 2022. These remaining future principal payments are projected to be funded from cash on hand and adjusted funds flow from operations. The Company has no available undrawn debt capacity under its credit facility. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination is expected in the second quarter of 2022. There can be no assurance that the borrowing base review will not result in a material reduction in the borrowing base, and that the necessary funds will be available for the Company to meet its obligations as they become due.
The Company's current forecast indicates that it will be able to fund the future principal payments due in 2021 and 2022 from cash and cash equivalents and adjusted funds flow from operations and that it will be in compliance with its debt covenants over the next year. These forecasts are based on current strip prices and the Company's current economic hedges and include a number of significant estimates and judgments that could change in the future.
The global impact of the COVID-19 virus pandemic has led to a high degree of volatility and uncertainty that continues to impact the energy industry and financial markets. While prices have increased significantly during 2021, there is still a great deal of uncertainty about the impact of the pandemic going forward which continues to have a continuing negative impact on the Company's ongoing operations and its ability to raise capital in the near future or on terms favorable to the Company.
The Company's ability to continue as a going concern is dependent upon the lender maintaining the borrowing base limit on the credit facility, obtaining a new credit facility or extending the terms of the existing credit facility and the Company's ability to generate net cash from operating activities or raise additional financing to continue to fund its working capital deficiency, debt repayments and capital expenditures. These matters cause material uncertainty which may cast significant doubt on the Company's ability to continue as a going concern.
The financial statements do not reflect adjustments that would be necessary if the going concern assumption was not appropriate. If the going concern assumption were not appropriate, adjustments would be necessary in the carrying value of the Company's assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used. These adjustments could be material.
Operating Summary
The Company's results of operations are dependent on production volumes of natural gas, crude oil and natural gas liquids and the prices received for the production. Prices for these commodities have shown significant volatility during recent years and are determined by supply and demand factors, including weather and general economic conditions.
OVERVIEW
Results at a Glance
Three Months ended | Nine Months ended | |||||||||||
September 30, | September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Financial (US $000 except per share) | ||||||||||||
Oil and gas gross revenues | 4,988 | 3,147 | 13,684 | 9,046 | ||||||||
Net operating income(1) | 3,168 | 1,793 | 8,510 | 4,996 | ||||||||
Net income (loss) | 608 | (616 | ) | (1,338 | ) | (69,332 | ) | |||||
Basic and diluted net income (loss) per share | 0.00 | (0.00 | ) | (0.01 | ) | (0.30 | ) | |||||
Cash flow from operating activities | 1,478 | 1,684 | 4,491 | 4,651 | ||||||||
Adjusted funds flow(2) | 1,736 | 1,893 | 4,710 | 5,446 | ||||||||
Additions to property, plant and equipment | 47 | 52 | 137 | (59 | ) | |||||||
Operating | ||||||||||||
Average production (Boepd) | 960 | 1,134 | 991 | 1,174 | ||||||||
Average price ($/BOE) | 56.49 | 30.16 | 50.58 | 28.12 | ||||||||
Netback from operations ($/BOE)(3) | 35.87 | 17.17 | 31.45 | 15.52 | ||||||||
Netback including commodity contracts ($/BOE)(3) | 27.04 | 24.90 | 25.08 | 23.38 | ||||||||
September 30, 2021 | June 30, 2021 | March 31, 2021 | December 31, 2020 | |||||||||
Balance Sheet | ||||||||||||
Cash and cash equivalents | 380 | 697 | 735 | 920 | ||||||||
Total assets | 79,373 | 79,984 | 81,251 | 82,184 | ||||||||
Working capital (deficiency) | (4,063 | ) | (21,377 | ) | (4,371 | ) | (3,456 | ) | ||||
Total non-current liabilities | 18,166 | 2,287 | 18,773 | 19,978 |
(1) Net operating income is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A. | ||||||
(2) Adjusted Funds Flow is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A. | ||||||
(3) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A. |
The average production for the third quarter of 2021 was 960 BOEPD, a decrease of 15% compared to third quarter 2020 production of 1,134 BOEPD. Average production for the nine months ended September 30, 2021 was 991 BOEPD, a decrease of 16% from the average production of 1,174 BOEPD in the same period of 2020. These decreases were due to the normal production decline of the Company's existing wells.
Gross revenues for the third quarter of 2021 increased by 59% compared to the third quarter of 2020. The increase was due to an 87% increase in average prices in the third quarter of 2021 partially offset by a 15% decrease in production in the third quarter of 2021 compared to 2020. Gross revenues for the nine months ended September 30, 2021 increased by 51% compared to the same period in 2020. The increase was due to an 80% increase in average prices in the nine months ended September 30, 2021 partially offset by the 16% decrease in production in the nine months ended September 30, 2021 compared to 2020.
Interest expense decreased by 21% in the third quarter of 2021 and 34% in the nine months ended September 30, 2021 compared to the comparable prior year periods due to lower interest rates and principal payments on the credit facility during 2021 which reduced the outstanding loan balance.
Netback from operations(2) increased to $35.87 per BOE in the third quarter of 2021 compared to $17.17 per BOE in the third quarter of 2020, an increase of 109%. Netback from operations(2) increased to $31.45 per BOE in the nine months ended September 30, 2021 compared to $15.52 per BOE in the nine months ended September 30, 2020, an increase of 103%. Netback including commodity contracts(2) for the third quarter of 2021 was $27.04 per BOE, an increase of 9% from the prior year third quarter. Netback including commodity contracts(2) for the nine months ended September 30, 2021 was $25.08 per BOE, an increase of 7% from the prior year period. The 2021 increases compared to the prior year are due to the increase in average prices offset by the increase in average operating expenses due mainly to higher production taxes.
Cash flow from operating activities was $1.5 million in third quarter of 2021 compared to $1.7 million in the prior year third quarter. Cash flow from operating activities was $4.5 million for the nine months ended September 30, 2021 compared to $4.7 million for the nine months ended September 30, 2020.
Adjusted funds flow(1) was $1.7 million for the third quarter of 2021 compared to $1.9 million for the prior year third quarter, a decrease of 11%. The decrease was primarily due to realized losses from commodity contracts in 2021 and a 15% decrease in production in the third quarter of 2021 compared to 2020 partially offset by the 58% increase in average prices in the third quarter of 2021. Adjusted funds flow(1) was $4.7 million for the nine months ended September 30, 2021 compared to $5.4 million for the prior year period, a decrease of 13%. The decrease was primarily due to realized losses from commodity contracts in 2021 and a 16% decrease in production in the nine months ended September 30, 2021 compared to 2020 partially offset by a 57% increase in average prices in the nine months ended September 30, 2021.
Operating expenses for the third quarter of 2021 increased by 10% compared to the prior year third quarter. Operating expenses for the nine months ended September 30, 2021 increased by 7% compared to the prior year period. The increase was primarily due to higher production taxes in 2021 due to higher prices.
General & administrative (G&A) expenses for the third quarter of 2021 decreased by 8% compared to the prior year third quarter due to cost cutting measures. G&A expenses for the nine months ended September 30, 2021 remained the same compared to the prior year period as the cost cutting measures were offset by higher advisor fees.
Net income in the third quarter of 2021 was $0.6 million, compared to a net loss of $0.6 million in the third quarter of 2020. The Company recorded less than $0.1 million unrealized loss from commodity contracts in the third quarter of 2021, compared to an unrealized loss of $1.1 million recorded in the third quarter of 2020.
Net loss for the nine months ended September 30, 2021 was $1.3 million, compared to a net loss of $69.3 million in the prior year period. The Company recorded an unrealized loss from commodity contracts of $3.0 million in the first nine months of 2021. In the first nine months of 2020, the Company recorded a PP&E impairment charge of $71.9 million.
In June 2021, the Company received a notice from the Small Business Administration (SBA) that the entire balance of the original Paycheck Protection Program (PPP) loan of $0.3 million had been forgiven and the Company recorded this amount as other income.
In September 2021, the Company's credit facility was re-determined at a borrowing base of $17.3 million at September 30, 2021. In addition, the term of the credit facility was extended to June 2023. In accordance with the redetermination, the Company has no available capacity on the credit facility and the borrowing base will be automatically reduced by the principal payments as they are paid. The Company will make additional principal payments to reduce the borrowing base to $16.0 million by April 2022. These future principal payments are projected to be funded from cash on hand and adjusted funds flow from operations. The next redetermination will be in the second quarter of 2022. There can be no assurance that the borrowing base review will not result in a material reduction in the borrowing base, and that the necessary funds will be available for the Company to meet its obligations as they become due.
(1) Adjusted funds flow is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
OPERATIONS UPDATE
Tishomingo Field, Ardmore Basin, Oklahoma
The average production for the third quarter of 2021 was 960 BOEPD, a decrease of 15% compared to third quarter 2020 production of 1,134 BOEPD. Average production for the nine months ended September 30, 2021 was 991 BOEPD, a decrease of 16% from the average production of 1,174 BOEPD in the same period of 2020. The Company has commodity contracts in place for almost 75% of its existing 2021 oil production at an average price of $48.89/barrel.
Production and Revenue | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||||
2021 | 2020 | % | 2021 | 2020 | % | |||||||||||||
Average oil production (BOPD) | 641 | 761 | (16 | ) | 671 | 802 | (16 | ) | ||||||||||
Average natural gas production (MCFPD) | 845 | 1,027 | (18 | ) | 877 | 1,042 | (16 | ) | ||||||||||
Average NGL production (BOEPD) | 178 | 202 | (12 | ) | 174 | 198 | (12 | ) | ||||||||||
Average production (BOEPD) | 960 | 1,134 | (15 | ) | 991 | 1,174 | (16 | ) | ||||||||||
Average oil price ($/bbl) | 69.61 | 38.70 | 80 | 62.96 | 35.75 | 76 | ||||||||||||
Average natural gas price ($/mcf) | 4.12 | 1.79 | 130 | 3.52 | 1.79 | 97 | ||||||||||||
Average NGL price ($/bbl) | 34.36 | 14.50 | 137 | 27.61 | 12.47 | 121 | ||||||||||||
Average price ($/BOE) | 56.49 | 30.16 | 87 | 50.58 | 28.12 | 80 | ||||||||||||
Oil revenue ($000) | 4,105 | 2,708 | 52 | 11,528 | 7,858 | 47 | ||||||||||||
Natural gas revenue ($000) | 320 | 169 | 89 | 842 | 511 | 65 | ||||||||||||
NGL revenue ($000) | 564 | 270 | 109 | 1,314 | 677 | 94 |
Oil production for the third quarter of 2021 was 641 BOPD compared to 761 BOPD for the third quarter of 2020, a decrease of 16%. Average oil production for the first nine months of 2021 was 671 BOPD compared to 802 BOPD for the same period in 2020, a decrease of 16%. The production decreases are due to the natural decline of existing wells. Oil revenue increased by 52% in the third quarter of 2021 versus the third quarter of 2020 due to an increase in oil prices of 80% partially offset by the production decrease. Oil revenue increased by 47% in the first nine months of 2021 versus the first nine months of 2020 due to an increase in oil prices of 76% partially offset by the production decrease.
For the third quarter of 2021, average natural gas production was 845 MCFPD compared to 1,027 MCFPD in the prior year third quarter, a decrease of 18%. Average natural gas production for the first nine months of 2021 was 877 MCFPD compared to 1,042 MCFPD for the first nine months of 2020. The production decreases are due to the natural decline of existing wells. Natural gas revenue increased by 89% in the third quarter of 2021 versus the third quarter of 2020 due to a 130% increase in natural gas prices partially offset by the production decrease. Natural gas revenue increased by 89% in the first nine months of 2021 versus the first nine months of 2020 due to a 97% increase in natural gas prices partially offset by the production decrease.
Natural gas liquids (NGL) production for the third quarter of 2021 decreased to 178 BOEPD from 202 BOEPD in the third quarter of 2020, a decrease of 12%. Average NGL production for the first nine months of 2021 decreased to 174 BOEPD from 198 BOEPD for the same period in 2020, a decrease of 12%. NGL revenue increased by 109% in the third quarter of 2021 compared to the prior year quarter due to an increase in NGL prices of 137% partly offset by the production decrease. NGL revenue increased by 94% in the first nine months of 2021 compared to the first nine months of 2020 due to an increase in NGL prices of 121% partly offset by the production decrease.
Average production was 960 BOEPD in the third quarter of 2021 compared to 1,134 BOEPD in the third quarter of 2020, a decrease of 15%. Average production was 991 BOEPD in the first nine months of 2021 compared to 1,174 BOEPD in the first nine months of 2020, a decrease of 16%. The decreases are due to the factors discussed above. Gross revenue for the third quarter of 2021 increased by 59% compared to the third quarter of 2020. Gross revenues for the first nine months of 2021 increased by 51% compared to the first nine months of 2020. The increases are due to an increase in average prices partially offset by the production decrease.
Royalties, Operating Expenses and Netback | ||||||||||||||||||
Three months ended September 30 | Nine months ended September 30 | |||||||||||||||||
($/BOE) | 2021 | 2020 | % | 2021 | 2020 | % | ||||||||||||
Average price | 56.49 | 30.16 | 87 | 50.58 | 28.12 | 80 | ||||||||||||
Less: Royalties | 12.22 | 6.53 | 87 | 10.96 | 6.15 | 78 | ||||||||||||
Less: Operating expenses | 8.40 | 6.46 | 30 | 8.17 | 6.45 | 27 | ||||||||||||
Netback from operations(1) | 35.87 | 17.17 | 109 | 31.45 | 15.52 | 103 | ||||||||||||
Price adjustment from commodity contracts(2) | (8.83 | ) | 7.73 | - | (6.37 | ) | 7.86 | - | ||||||||||
Netback including commodity contracts(1) | 27.04 | 24.90 | 9 | 25.08 | 23.38 | 7 |
(1) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Price adjustment from commodity contracts includes the positive or negative adjustment to the average price per barrel that the Company realized from its commodity contracts. See the listing of commodity contracts below.
The average price increase in the third quarter of 2021 was due to price increases in oil, gas and NGLs. Oil made up 68% of the production mix in 2021 compared to 67% of the production mix in the third quarter of 2020. The average price increase in the first nine months of 2021 was due to price increases in oil, gas and NGLs. Oil made up 68% of the production mix in 2021 compared to 68% of the production mix in the first nine months of 2020.
Royalties on Tishomingo production averaged approximately 21.6% for both the third quarters of 2021 and 2020. Royalties on Tishomingo production averaged approximately 21.7% for the first nine months of 2021 versus 21.9% in the first nine months of 2020. The difference in percentages is due to different royalty burdens on the leases drilled by the Company.
Major operating expenses are related to the gathering and processing of natural gas and NGLs as well as periodic well repairs and maintenance. Operating expenses in the third quarter of 2021 were $742,000 compared to $674,000 in the third quarter of 2020. Operating expenses averaged $8.40 per BOE for the third quarter of 2021 compared to $6.46 per BOE for the same period in 2020. The increase was mainly due to higher production taxes in the third quarter of 2021 which were $2.86 per BOE compared to $1.37 per BOE in the prior year third quarter. Operating expense per boe excluding production taxes for the third quarter of 2021 increased by 9% compared to the prior year quarter. Operating expenses averaged $8.17 per BOE for the first nine months of 2021 compared to $6.45 per BOE for the same period in 2020. The increase was due to higher production taxes in the first nine months of 2021 which were $2.59 per BOE compared to $1.75 per BOE in the prior year third quarter. Operating expense per boe excluding production taxes for the first nine months of 2021 increased by 19% compared to the prior year period due to one-time field maintenance costs.
Realized and Unrealized Gains and Losses from Risk Management Contracts
The Company has entered into financial commodity contracts which are summarized in the table below. Total Volume Hedged in the table is the annual volumes and Price is the fixed price specified in the financial commodity contracts.
At September 30, 2021 the following financial commodity contracts were outstanding and recorded at estimated fair value:
|
| Total Volume | Price |
Commodity | Period | (BBLS) | ($/BBL) |
Oil - WTI | October 1, 2021 to December 31, 2021 | 18,000 | $52.66 |
Oil - WTI | October 1, 2021 to December 31, 2021 | 15,000 | $42.32 |
Oil - WTI | January 1, 2022 to September 30, 2022 | 54,000 | $55.92 |
Oil - WTI | October 1, 2021 to December 31, 2021 | 3,000 | $59.15 |
Oil - WTI | January 1, 2022 to September 30, 2022 | 36,000 | $56.70 |
Oil - WTI | October 1, 2022 to December 31, 2022 | 30,000 | $57.05 |
Oil - WTI | January 1, 2023 to May 31, 2023 | 45,000 | $56.02 |
The estimated fair value results in a $3.0 million liability as of September 30, 2021 (December 31, 2020: $0.04 million liability) for the financial oil and gas contracts which has been determined based on the prospective amounts that the Company would receive or pay to terminate the contracts, consisting of a long term liability of $0.7 million and a current liability of $2.3 million, (December 31, 2020: current liability of $0.04 million).
In October 2021, the Company entered into the following additional financial commodity contracts:
|
| Total Volume | Price |
Commodity | Period | ($/BBL or | |
Oil - WTI | June 1, 2023 to December 31, 2023 | 63,000 | $64.90 |
Oil - WTI | January 1, 2024 to May 31, 2024 | 40,000 | $62.77 |
The realized and unrealized gains/losses from the financial commodity contracts are as follows:
($000s) | Three months ended | Nine months ended | ||||||||||
September 30, | September 30, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Realized gain (loss) on financial commodity contracts | (780) | 806 | (1,722) | 2,529 | ||||||||
Unrealized gain (loss) on financial commodity contracts | (11) | (1,084) | (2,953) | 1,879 |
General and Administrative Expenses
G&A expense for the third quarter of 2021 was $650,000 compared to $709,000 for the same period of 2020, a decrease of 8%. The decrease was due to the Company's cost cutting measures. G&A expense for the first nine months of 2021 was $2,075,000 compared to $2,082,000 for the same period of 2020, a decrease of less than 1%. The decreases are due to cost cutting by the Company partially offset by higher advisor fees.
Depletion and Depreciation
Depletion and depreciation expense for the third quarter of 2021 was $874,000 compared to $1,118,000 in the same period of 2020. Depletion and depreciation expense for the first nine months of 2021 was $2.7 million compared to $3.6 million in the same period of 2020. The decrease in both periods is due to decreased production compared to the prior year periods. For the first nine months of 2021, the decrease was also due to higher PP&E balance before the impairment in 2020. Depletion and depreciation expense on a per barrel basis was $9.89 for the third quarter of 2021 compared to $10.71 for the third quarter of 2020. Depletion and depreciation expense on a per barrel basis was $9.90 for the first nine months of 2021 compared to $11.27 for the first nine months of 2020.
Interest on loans and borrowings
Interest on loans and borrowings decreased from $299,000 for the third quarter of 2020 to $237,000 for the third quarter of 2021. Interest on loans and borrowings decreased from $1,064,000 for the first nine months of 2020 to $700,000 for the first nine months of 2021. The decreases were due to lower interest rates and principal payments on the credit facility during 2021 which reduced the outstanding loan balance.
Net income (loss) for the period
The Company had net earnings of $608,000 ($0.00 per share) for the third quarter of 2021 compared to net loss of $616,000 ($0.00 per share) for the same period of 2020. The net earnings in the third quarter of 2021 compared to the net loss in the same period in 2020 is due to an increase in revenue net of royalties of $1,442,000, a decrease in depletion, depreciation and accretion of $244,000, a decrease in interest on loans and borrowings of $62,000, a decrease in G&A expense of $59,000 partially offset by realized and unrealized losses in financial commodity contracts in the third quarter of 2021 totaling $791,000 versus losses of $278,000 in the third quarter of 2020 and an increase in operating expenses of $68,000.
The Company had net loss of $1,338,000 ($0.01 per share) for the first nine months of 2021 compared to net loss of $69,332,000 ($0.30 per share) for the same period of 2020. The decrease in net loss in the first nine months of 2021 compared to the net loss in the same period in 2020 is due to an impairment of property, plant and equipment of $71,923,000 in 2020, an increase in revenue net of royalties of $3,647,000, a decrease in depletion, depreciation and accretion of $947,000, a decrease in interest on loans and borrowings of $364,000, an increase in other income of $303,000, partially offset by realized and unrealized losses in financial commodity contracts in the first nine months of 2021 totaling $4,675,000 versus gains of $4,408,000 in the first nine months of 2020 and an increase in operating expenses of $135,000.
Cash from operating activities
Cash flows from operating activities for the third quarter of 2021 was $1,478,000 compared to cash flows from operating activities of $1,684,000 for the same period in 2020. Cash flows from operating activities for the first nine months of 2021 was $4,491,000 compared to cash flows from operating activities of $4,651,000 for the same period in 2020.
CAPITAL EXPENDITURES
Capital expenditures for the nine months ended September 30, 2021 were for the Tishomingo field located in Oklahoma.
($000) | ||||||
2021 | 2020 | |||||
Additions (adjustments) to oil and gas properties | $ | 137 | $ | (59 | ) | |
$ | 137 | $ | (59 | ) |
LIQUIDITY AND CAPITAL RESOURCES | ||||||
($000, except shares) | ||||||
At September 30, 2021 | At December 31, 2020 | |||||
Working Capital Deficiency (US$) | $ | (4,063 | ) | $ | (3,456 | ) |
Loans and Borrowings (US$) | $ | 17,446 | $ | 20,749 | ||
Shares Outstanding, end of period | 232,922,625 | 232,922,625 | ||||
Market Price per share, end of period (in Canadian $) | $ | 0.09 | $ | 0.06 | ||
Market Value of Shares (in Canadian $) | $ | 20,963 | $ | 13,975 |
In June 2017, the Company's US subsidiary obtained a new credit facility from BOK Financial, which is secured by the US subsidiary's interests in the Tishomingo Field. The credit facility is intended to fund the drilling of the Caney wells in the Tishomingo Field and expires in June 2023. At September 30, 2021 loans and borrowings of $17.3 million (December 31, 2020: $20.7 million) are presented net of loan acquisition costs of $0.2 million (December 31, 2020: $0.2 million). Subsequent to the quarter end, the Company made principal payments of $0.2 million.
In September 2021, the credit facility was redetermined at a borrowing base of $17.3 million at September 30, 2021. In addition, the term of the credit facility was extended until June 2023. In accordance with the redetermination, the Company has no available capacity on the credit facility and the borrowing base is automatically reduced by the principal payments as they are paid. In addition, the Company is required to make additional principal payments to reduce the borrowing base to $16.0 million by April 2022. These future principal payments are projected to be funded from cash on hand and adjusted funds flow from operations. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination will be in the second quarter of 2022. Future commitment amounts will be subject to new reserve evaluations and there is no guarantee that the size and terms of the credit facility will remain the same after the borrowing base redetermination. Any redetermination of the borrowing base is effective immediately and if the borrowing base is reduced, the Company has six months to repay any shortfall.
The credit facility has two primary debt covenants. One covenant requires the US subsidiary to maintain a positive working capital balance which includes any unused excess borrowing capacity and excludes the fair value of commodity contracts, the current portion of long-term debt (the "Current Ratio") and certain payables to an operator that are being reduced by the revenue earned from the non-operated well. The second covenant ensures the ratio of outstanding debt and long-term liabilities to an annualized quarterly adjusted EBITDA amount (the "Maximum Leverage Ratio") be no greater than 4 to 1 at any quarter end. Adjusted EBITDA is defined as net income excluding interest expense, depreciation, depletion and amortization expense, and other non-cash and non-recurring charges including severance, stock based compensation expense and unrealized gains or losses on commodity contracts.
The Company was in compliance with both covenants for the quarter ended September 30, 2021. At September 30, 2021, the Current Ratio of the US subsidiary was 1.16 to 1.0 and the Maximum Leverage Ratio was 2.98 to 1.0 for the three months ended September 30, 2021.
The current global and market volatility, including the continuing uncertainty due to the impact of the COVID-19 pandemic, impacts the ability to prepare financial forecasts. The Company's current forecast indicates that it will be able to fund the 2021 and 2022 principal payments from cash on hand and adjusted funds flow from operations and that it will be in compliance with its debt covenants over the next twelve months. These forecasts are based on current strip prices and the Company's current hedges and they include a significant amount of estimates and judgments that could change in the future. If circumstances change and a covenant violation does occur and the Company does not obtain a waiver, this will represent an event of default under the facility and the lender will have the right to demand repayment of all amounts owed under the facility.
In April 2020, the Company's US subsidiary obtained a loan under the Paycheck Protection Program ("PPP") which is being administered by the Small Business Administration ("SBA"). The loan amount is $0.3 million with a 5-year term at an annual interest rate of 1 percent. All interest payments are deferred for the first ten months after the end of the loan forgiveness period, which is twenty-four weeks from the initiation of the loan. The loan amount may be forgiven if the proceeds are used for eligible expenditures, which include payroll costs, rent expense and utilities, in the twenty-four week forgiveness period. In June 2021, the Company received a notice from the SBA that the entire balance of $0.3 million had been forgiven and the Company recorded this amount as other income.
In February 2021, the US subsidiary obtained a loan under the PPP2 loan program for an additional $0.3 million. The PPP2 loan has the same terms as the original PPP loan and may also be forgiven if the proceeds are used for eligible expenditures.
At September 30, 2021, the Company had negative working capital of $4.1 million, versus negative working capital of $3.5 million at December 31, 2020. The Company does not have any drilling commitments and closely monitors its working capital and borrowing capacity to ensure adequate funds are available to finance its administrative and operating requirements. If additional drilling is not completed, the Company's production will continue to fall due to the normal decline of the existing wells.
The Company has entered into financial commodity contracts as part of its risk management strategy to manage its cash flow for future activity and to offset commodity price fluctuations. Other potential sources of cash flow include proceeds from additional debt or equity offerings but there is no guarantee that additional financing will be available when needed.
CONTRACTUAL OBLIGATIONS
The following are the contractual maturities of financial liabilities, excluding estimated interest payments at September 30, 2021:
$(000) | Total | 2021 | 2022 | 2023 | 2024 | Thereafter | ||||||||||||
Loans and borrowings * | $ | 17,446 | $ | 300 | $ | 1,000 | $ | 15,866 | $ | - | $ | 280 | ||||||
Trade and other payables | 3,285 | 3,285 | - | - | - | - | ||||||||||||
Lease payable | 60 | 60 | - | - | - | - | ||||||||||||
$ | 20,791 | $ | 3,645 | $ | 1,000 | $ | 15,866 | $ | - | $ | 280 |
* Except for the principal payments required in connection with the September 2021 redetermination, the Credit Facility provides for interest only payments until the June 2023 maturity date. The Company is required to repay amounts owing under the Credit Facility in full on the June 2023 maturity date. See "Liquidity and Capital Resources" and "Principal Business Risks" for discussion of events that would require early repayment of the Credit Facility.
QUARTERLY SUMMARY
Below is a summary of the Company's performance over the last eight quarters:
2021 | 2020 | 2019 | ||||||||||||||||||||||
($000, except as noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||
Daily Production | ||||||||||||||||||||||||
Oil (BOPD) | 641 | 674 | 697 | 735 | 761 | 804 | 842 | 923 | ||||||||||||||||
Natural gas (MCFPD) | 845 | 889 | 898 | 924 | 1,027 | 1,033 | 1,067 | 1,063 | ||||||||||||||||
NGLs (BOEPD) | 178 | 172 | 173 | 193 | 202 | 187 | 205 | 246 | ||||||||||||||||
Average production (BOEPD) | 960 | 994 | 1,020 | 1,082 | 1,134 | 1,163 | 1,225 | 1,346 | ||||||||||||||||
2021 | 2020 | 2019 | ||||||||||||||||||||||
($000, except as noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||
Average Price | ||||||||||||||||||||||||
Oil ($/bbl) | 69.61 | 63.77 | 55.92 | 40.42 | 38.70 | 23.35 | 44.88 | 55.13 | ||||||||||||||||
Natural gas ($/mcf) | 4.12 | 2.86 | 3.60 | 2.52 | 1.79 | 1.63 | 1.95 | 2.24 | ||||||||||||||||
NGL ($/bbl) | 34.36 | 23.96 | 24.15 | 14.39 | 14.50 | 7.00 | 15.43 | 15.61 | ||||||||||||||||
Average price ($/bbl) | 56.47 | 49.97 | 45.48 | 32.19 | 30.16 | 18.72 | 35.15 | 42.41 |
2021 | 2020 | 2019 | ||||||||||||||||||||||
($000, except as noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||
Netback(1) | ||||||||||||||||||||||||
Average price ($/BOE) | 56.49 | 49.97 | 45.48 | 32.19 | 30.16 | 18.72 | 35.15 | 42.41 | ||||||||||||||||
Royalties | 12.22 | 10.86 | 9.86 | 6.97 | 6.53 | 4.24 | 7.60 | 9.13 | ||||||||||||||||
Operating expenses | 8.40 | 8.81 | 7.30 | 6.84 | 6.46 | 6.07 | 6.80 | 7.71 | ||||||||||||||||
Netback from operations(1) | 35.87 | 30.30 | 28.32 | 18.38 | 17.17 | 8.41 | 20.75 | 25.57 | ||||||||||||||||
Price adjustment from commodity contracts | (8.83 | ) | (6.81 | ) | (3.55 | ) | 7.02 | 7.73 | 12.74 | 3.35 | (1.21 | ) | ||||||||||||
Netback including commodity contracts(1) | 27.04 | 23.49 | 24.77 | 25.40 | 24.90 | 21.15 | 24.10 | 24.36 | ||||||||||||||||
2021 | 2020 | 2019 | ||||||||||||||||||||||
($000, except as noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||
Net operating income(2) | ||||||||||||||||||||||||
Oil and gas revenue | 4,988 | 4,520 | 4,176 | 3,204 | 3,147 | 1,981 | 3,918 | 5,252 | ||||||||||||||||
Royalties | 1,079 | 981 | 907 | 694 | 680 | 449 | 847 | 1,131 | ||||||||||||||||
Operating expenses | 742 | 797 | 670 | 681 | 674 | 642 | 758 | 955 | ||||||||||||||||
3,167 | 2,742 | 2,599 | 1,829 | 1,793 | 890 | 2,313 | 3,166 | |||||||||||||||||
2021 | 2020 | 2019 | ||||||||||||||||||||||
($000, except as noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | ||||||||||||||||
Net earnings (loss) | 608 | (1,418 | ) | (528 | ) | (1,078 | ) | (616 | ) | (2,369 | ) | (66,492 | ) | (1,650 | ) | |||||||||
Basic and Fully Diluted Earnings (loss) per $/share | 0.00 | (0.01 | ) | 0.00 | 0.00 | 0.00 | (0.01 | ) | (0.29 | ) | (0.01 | ) | ||||||||||||
Adjusted funds flow(3) | 1,736 | 1,465 | 1,509 | 1,737 | 1,893 | 1,601 | 1,952 | 1,674 | ||||||||||||||||
Cash flow from operating activities | 1,478 | 1,649 | 1,364 | 1,460 | 1,684 | 1,050 | 1,917 | 869 | ||||||||||||||||
Bank debt | 17,446 | 18,451 | 19,808 | 20,749 | 21,552 | 22,720 | 26,190 | 27,164 | ||||||||||||||||
Total assets | 79,373 | 79,984 | 81,251 | 82,184 | 85,034 | 86,411 | 92,782 | 161,208 |
(1) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Net operating income is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(3) Adjusted funds flow is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
Quarterly Variability
Fluctuations in quarterly results are due to a number of factors, some of which are not within the Company's control such as:
- Oil, gas and NGL price changes due to market conditions.
- Changes in production resulting from fluctuations in drilling and completions and shut-in of wells.
- The changes in G&A expense from quarter to quarter reflect changes in operations, changes in personnel, and non-recurring charges related to specific transactions or events.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the consolidated financial statements requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities, the disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the financial statements. Accordingly, actual results may differ from the estimated amounts. Significant estimates and judgments made by management in the preparation of the consolidated financial statements are as follows:
Oil and gas assets
Development and production assets are assessed for recoverability at cash generating unit ("CGU") level. The determination of CGUs is subject to management judgments. Recoverability is assessed by comparing the carrying value of the asset to its estimated recoverable amount, which is based on the higher of fair value of the assets less the cost to sell ("FVLCS") or value in use ("VIU"). The significant estimates used in the determination of the estimated recoverable amount include the following:
- Proved and probable oil and gas reserves and the related cash flows - Significant assumptions that are valid at the time of oil and gas reserve estimation may change significantly when additional information becomes available. Estimates of economically recoverable proved and probable oil and gas reserves and the related cash flows are based upon a number of significant assumptions, such as forecasted production, forecasted oil and gas commodity prices, forecasted operating costs, forecasted royalty costs, and forecasted future development costs. Changes in forecasted oil and gas commodity price assumptions, costs or recovery rates may change the economic status of proved and probable oil and gas reserves and may ultimately result in a restatement of proved and probable oil and gas reserves. Independent third-party reserve evaluators are engaged at least annually to estimate proved and probable oil and gas reserves and the related cash flows from the Company's interest in oil and gas properties.
- Discount rate - The discount rate used to calculate the net present value of cash flows is based on estimates of an industry peer group weighted average cost of capital. Changes in the economic environment could result in significant changes to this estimate.
Depletion of oil and gas assets
Depletion of oil and gas assets is determined based on total proved and probable oil and gas reserve volumes and includes future development costs as estimated by the Company's independent third-party reserve evaluators. By their nature, the estimates of proved and probable oil and gas reserves and the related cash flows are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.
Asset retirement obligations
The provisions for site restoration and abandonment is based on current legal requirements, technology, price levels and expected plans and are based on significant assumptions such as inflation rate and discount rate. Actual costs and cash outflows can differ from estimates because of changes in laws or regulations, market conditions and changes in technology.
Derivative instruments
The estimated fair value of derivative financial instruments resulting in financial assets and liabilities, by their very nature is subject to estimation, due to the use of future oil and natural gas prices and the volatility in these prices.
Compensation costs
Compensation costs recognized for share based compensation plans are subject to the estimation of what the ultimate payout will be using pricing models such as Black-Scholes model which is based on assumptions such as volatility, forfeiture rate, interest rate and expected term.
Income taxes
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such income taxes are subject to measurement uncertainty. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.
Liquidity
The Company's approach to managing liquidity is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company's reputation.
Typically the Company ensures that it has sufficient cash on demand and cash flow from operations to meet expected operational expenses for a one-year period, including the servicing of financial obligations; this excludes the potential impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters. To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditure. The Company also attempts to match its payment cycle with collection of oil revenue on the 20th of each month.
The Company monitors its expected cash inflows from trade and other receivables and its expected cash outflows on trade and other payables and principal debt payments. The Company will make principal debt payments of $1.3 million by April 1, 2022 and will utilize its cash on hand and cash inflows to fund these principal payments as well as its trade payables. The current challenging economic climate may lead to adverse changes in cash flow, working capital levels or debt balances, which may also have a direct impact on the Company's results and financial position. These and other factors may adversely affect the Company's liquidity and the Company's ability to generate profits in the future.
OUTSTANDING SHARE DATA
There were 232,922,625 common shares outstanding as of both November 4, 2021 and September 30, 2021. The Company had 1,750,000 stock options outstanding as of both November 4, 2021 and September 30, 2021.
PRINCIPAL BUSINESS RISKS
KEI's business and results of operations are subject to a number of risks and uncertainties, including but not limited to the following:
- the uncertainty of finding oil and gas in commercial quantities
- securing markets for existing and future production
- commodity price fluctuations due to market forces including the impact of COVID-19
- financial risk due to foreign exchange rates and interest rate exposure
- changes to government regulations in the United States, including regulations relating to prices, taxes, royalties and environmental protection
- changing government policies and regulations, social instability and other political, economic or diplomatic developments in the countries in which the Company operates
- the ability to fund wells drilled in non-operated sections of the Tishomingo field
- the uncertainty of pipeline repairs leading to temporary shutting-in of wells
- availability of equity or debt financing is affected by many factors many of which are beyond the control of the Company
- uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom
- the oil and gas industry is intensely competitive and the Company competes with a large number of companies with greater resources
- risks related to the Credit Facility, including the risk that the Company could be required under the terms of the Credit Facility to prepay the outstanding principal amount and other amounts owing under the Credit Facility in certain circumstances, some of which are out of the Company's control, including failure to comply with financial ratio tests, borrowing base redeterminations, Mr. Wolf Regener ceasing to be the President of Kolibri Global Energy Inc., certain changes to the board of directors of the Company and the acquisition by any person or persons acting jointly or in concert of 25% or more of the Company's shares. The Company is required to repay amounts owing under the Credit Facility in full on the June 2023 maturity date. There can be no assurance that the Company will be able to obtain sufficient capital to repay the Credit Facility or that the Company will be able to extend or refinance the Credit Facility. A failure by the Company to perform its obligations under the Credit Facility could result in, among other adverse effects, the loss of the Company's Tishomingo Field assets. A copy of the Amended and Restated Credit Agreement was filed on SEDAR on June 26, 2017. See "Liquidity and Capital Resources" and "Contractual Obligations" above and the "Risk Factors" section in the Company's most recent Annual Information Form.
- the other risks identified in the Company's most recent Annual Information Form under the "Risk Factors" section and the Company's other public disclosure, available under the Company's profile on SEDAR at www.sedar.com.
The Company seeks to mitigate these risks by:
- maintaining product mix to manage exposure to commodity price risk
- monitoring production trends to maximize the potential of its capital spending program
- from time to time, entering into financial commodity contracts to hedge against commodity price risk
- ensuring strong third-party operators for non-operated properties
- transacting with creditworthy counterparties
- monitoring commodity prices and capital programs to manage cash flow
- reviewing proposed changes in applicable government regulations and laws to assess the impact on the Company's operations
DISCLOSURE CONTROLS AND PROCEDURES
The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICOFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements in accordance with IFRS.
The DC&P have been designed to provide reasonable assurance that material information relating to KEI is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by KEI under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation.
The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR and DC&P that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR. No changes in ICOFR and DC&P were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's ICOFR during the quarter ended September 30, 2021.
It should be noted that a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.
OUTLOOK
In the United States, the Company intends to drill and complete additional wells in the Caney/Sycamore formations on its Oklahoma lands as financing becomes available and the economic environment changes. In addition, the Company continues to utilize its technical and operational expertise to identify and acquire additional oil, gas and clean energy projects.
NON-GAAP MEASURES
Netback from operations, netback including commodity contracts, net operating income and adjusted funds flow (collectively, the "Company's Non-GAAP Measures") are not measures recognized under Canadian generally accepted accounting principles ("GAAP") and do not have any standardized meanings prescribed by GAAP. Management of the Company believes that such measures are relevant for evaluating returns on each of the Company's projects as well as the performance of the enterprise as a whole. The Company's Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures as reported by such organizations. The Company's Non-GAAP Measures should not be construed as alternatives to net income, cash flows related to operating activities, working capital or other financial measures determined in accordance with GAAP, as an indicator of the Company's performance.
Netback from operations per barrel and its components are calculated by dividing revenue, less royalties and operating expenses by the Company's sales volume during the period. Netback including commodity contracts is calculated by adjusting netback from operations by the realized gains or losses received from commodity contracts during the period. Netback is a non-GAAP measure but it is commonly used by oil and gas companies to illustrate the unit contribution of each barrel produced. The Company believes that the netback is a useful supplemental measure of the cash flow generated on each barrel of oil equivalent that is produced in its operations. However, non-GAAP measures do not have any standardized meaning prescribed by GAAP and therefore, may not be comparable to similar measures used by other companies and should not be used to make comparisons.
The following is the reconciliation of the non-GAAP measure netback from operations to net income (loss) from continuing operations:
(US $000) | Three months ended September 30, | Nine months ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Net income (loss) | 608 | (616 | ) | (1,338 | ) | (69,332 | ) | |||||
Adjustments: | ||||||||||||
Finance income | - | (809 | ) | - | (4,410 | ) | ||||||
Finance expense | 1,036 | 1,392 | 5,397 | 1,088 | ||||||||
Stock based compensation | - | - | - | 21 | ||||||||
General and administrative expenses | 650 | 709 | 2,075 | 2,082 | ||||||||
Depletion, depreciation and amortization | 874 | 1,118 | 2,679 | 3,626 | ||||||||
Impairment of PP&E | - | - | - | 71,923 | ||||||||
Other income | - | (1 | ) | (303 | ) | (2 | ) | |||||
Operating netback | 3,168 | 1,793 | 8,510 | 4,996 | ||||||||
Netback from operations per BOE | 35.87 | 17.17 | 31.45 | 15.52 |
Net operating income is similarly a non-GAAP measure that represents revenue net of royalties and operating expenses. The Company believes that net operating income is a useful supplemental measure to analyze operating performance and provides an indication of the results generated by the Company's principal business activities prior to the consideration of other income and expenses.
The following is the reconciliation of the non-GAAP measure net operating income:
(US $000) | Three months ended September 30, | Nine months ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Oil and gas revenue, net of royalties | 3,909 | 2,467 | 10,717 | 7,070 | ||||||||
Operating expenses | 742 | 674 | 2,209 | 2,074 | ||||||||
Net operating income | 3,167 | 1,793 | 8,508 | 4,996 |
Adjusted funds flow is calculated as cash from operating activities excluding changes in non-cash operating working capital and interest expense. The Company considers this a key measure as it demonstrates its ability to generate funds from operations necessary for future growth excluding the impact from short-term fluctuations in the collection of accounts receivable and the payment of accounts payable and financing costs. The following is the reconciliation of the non-GAAP measure adjusted funds flow:
(US $000) | Three months ended September 30, | Nine months ended September 30, | ||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Cash flow from continuing operations | 1,478 | 1,684 | 4,491 | 4,651 | ||||||||
Change in non-cash working capital | 51 | (60 | ) | (392 | ) | (184 | ) | |||||
Interest expense(a) | 207 | 269 | 611 | 979 | ||||||||
Adjusted funds flow | 1,736 | 1,893 | 4,710 | 5,446 |
(a) Interest expense on long-term debt excluding the amortization of debt issuance costs
CAUTIONARY STATEMENTS
(a) The Company's natural gas production is reported in thousands of cubic feet ("Mcfs"). The Company also uses references to barrels ("Bbls") and barrels of oil equivalent ("BOEs") to reflect natural gas liquids and oil production and sales. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
(b) Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value.
(c) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
(d) This MD&A and the Company's other public disclosure contains peak and 30-day initial production rates and other short-term production rates. Readers are cautioned that initial production rates are preliminary in nature and are not necessarily indicative of long-term performance or of ultimate recovery.
CAUTION REGARDING FORWARD-LOOKING INFORMATION
This MD&A contains forward-looking information including expectations regarding the Company's reserve-based loan facility, including scheduled repayments, proposed timing and expected results of exploratory and development work in the Company's Tishomingo Field, expected productivity from current and future wells, planned capital expenditure programs and cost estimates, the effect of design and performance improvements on future productivity, planned use and sufficiency of proceeds from the Company's debt and equity financings, cash on hand and cash flow from operations and the Company's strategy and objectives. The use of any of the words "target", "plans", "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe","intend" and similar expressions are intended to identify forward-looking statements.
Such forward-looking information is based on management's expectations and assumptions, including that the Company's geologic and reservoir models and analysis will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled, declines will match the modeling, future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management's expectations, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that well shut-ins will not materially reduce production or adversely affect future productivity, that anticipated results and estimated costs will be consistent with managements' expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the combination of cash on hand and cash flow from operations will be sufficient to finance the Company's cash requirements through 2021, that the Company will continue to be able to access sufficient capital through financings, credit facilities, farm-ins or other participation arrangements to maintain its projects, that the Company will continue in compliance with the covenants under its reserve-based loan facility and that the borrowing base will not be reduced, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company's business and its ability to advance its business strategy.
Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward looking information is based vary or prove to be invalid, including that the Company's geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with managements' expectations, that the Company will not achieve a comparable level of hedging going forward in respect of its existing production, that the Company will not achieve the results anticipated by management from the Company's cost reduction measures, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks, including flooding and extended interruptions due to inclement or hazardous weather conditions), well shut-ins and the potential for damage to the affected wells, the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company's assumptions, that very low or no production rates are achieved, that the Company will cease to be in compliance with the covenants under its reserve-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base redetermination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company's most recent Annual Information Form under the "Risk Factors" section and the Company's other public disclosure, available under the Company's profile on SEDAR at www.sedar.com.
Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this MD&A is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.
CORPORATE INFORMATION
DIRECTORS AND OFFICERS | AUDITORS |
KPMG LLP | |
David Neuhauser 1,2,3,5 | Calgary, AB |
Director, Chairman of the Board | |
BANKERS | |
Eric Brown 1,2,3,4,5 | Amegy Bank National Association |
Director | Denver, CO, USA |
Leslie O'Connor 1,2,3,4,5 | HSBC Bank Canada |
Director | Calgary, AB |
Wolf Regener 4 | BOK Financial |
Director, President and Chief Executive Officer | Tulsa, OK |
Gary Johnson | CONSULTING ENGINEERS |
Chief Financial Officer and Vice President | Netherland, Sewell & Associates, Inc. |
Houston, TX, USA | |
1 Member of the Audit Committee | |
2 Member of the Corporate Governance Committee | TRANSFER AGENT AND REGISTRAR |
3 Member of the Compensation Committee | Computershare Trust Company |
4 Member of the HS&E Committee | Calgary, AB |
5 Member of the Reserves Committee | |
STOCK EXCHANGE LISTING | HEAD OFFICE |
The Toronto Stock Exchange | Suite 207, 3623 Old Conejo Road |
Trading Symbol: KEI | Newbury Park, CA, USA 91320 |
Over the Counter (OTC) QB | Telephone: (805) 484-3613 |
Trading Symbol: KGEIF | Fax: (805) 484-9649 |
LEGAL COUNSEL | CANADIAN OFFICE |
DuMoulin Black LLP | 10th Floor, 595 Howe Street |
Vancouver, BC | Vancouver, BC, Canada V6C 2T5 |
Telephone (604) 687-1224 | |
Fax: (604) 687-3635 |